UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June~~Sept. 30, 2018 or



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-03789

Southwestern Public Service Company

(Exact name of registrant as specified in its charter)



New Mexico		75-0575400
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

790 South Buchanan Street
Amarillo, Texas		79101
(Address of principal executive offices)		(Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer ¨		Accelerated filer ¨
Non-accelerated filer x		Smaller reporting company ¨
~~(Do not check if smaller reporting company)~~		Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class		Outstanding at ~~July 27,~~Oct. 26, 2018
Common Stock, $1 par value		100 shares

Southwestern Public Service Company meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

TABLE OF CONTENTS



PART I — FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2322
Item 4 —	Controls and Procedures	2625

PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	2726
Item 1A —	Risk Factors	2726
Item 6 —	Exhibits	2726

SIGNATURES		2827

Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

This Form 10-Q is filed by Southwestern Public Service Company, a New Mexico corporation (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and SPS. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries. Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).

PART 1 — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)


	Three Months Ended June 30						Six Months Ended June 30						Three Months Ended Sept. 30						Nine Months Ended Sept. 30,
	2018			2017			2018			2017			2018			2017			2018			2017
Operating revenues	$	481,338		$	479,796		$	928,570		$	939,868		$	540,063		$	551,623		$	1,468,633		$	1,491,491

Operating expenses
Electric fuel and purchased power	257,642			267,942			511,586			521,627			284,006			294,400			795,592			816,027
Operating and maintenance expenses	66,148			69,421			132,216			145,561			71,444			65,540			203,660			211,101
Demand side management expenses	4,779			3,691			8,937			7,566			4,590			4,236			13,527			11,802
Depreciation and amortization	49,579			46,815			97,995			97,233			52,204			47,548			150,199			144,781
Taxes (other than income taxes)	15,629			16,689			33,219			33,479			16,814			16,743			50,033			50,222
Total operating expenses	393,777			404,558			783,953			805,466			429,058			428,467			1,213,011			1,233,933

Operating income	87,561			75,238			144,617			134,402			111,005			123,156			255,622			257,558

Other expense, net	(782		)	(613		)	(1,486		)	(1,331		)	(1,026		)	(464		)	(2,512		)	(1,795		)
Allowance for funds used during construction — equity	3,201			1,869			6,618			4,004			5,019			2,453			11,637			6,457

Interest charges and financing costs
Interest charges — includes other financing costs of $702, $581, $1,396, and $1,156, respectively	20,621			21,946			40,776			44,684
Interest charges — includes other financing costs of $710, $625, $2,106, and $1,781, respectively													21,006			21,444			61,782			66,128
Allowance for funds used during construction — debt	(1,532		)	(1,128		)	(3,303		)	(2,467		)	(2,223		)	(1,349		)	(5,526		)	(3,816		)
Total interest charges and financing costs	19,089			20,818			37,473			42,217			18,783			20,095			56,256			62,312

Income before income taxes	70,891			55,676			112,276			94,858			96,215			105,050			208,491			199,908
Income taxes	12,440			20,314			20,726			34,441			14,674			37,269			35,400			71,710
Net income	$	58,451		$	35,362		$	91,550		$	60,417		$	81,541		$	67,781		$	173,091		$	128,198

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)


	Three Months Ended June 30,				Six Months Ended June 30				Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2018		2017		2018		2017		2018		2017		2018		2017
Net income	$	58,451	$	35,362	$	91,550	$	60,417	$	81,541	$	67,781	$	173,091	$	128,198

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $5, $9, $10 and $18, respectively	18		15		37		30
Amortization of losses included in net periodic benefit cost, net of tax of $5, $9, $15 and $27, respectively									18		16		55		46

Derivative instruments:
Reclassification of losses to net income, net of tax of $4, $6, $7 and $12, respectively	12		10		24		19
Reclassification of losses to net income, net of tax of $3, $6, $10 and $18, respectively									13		10		37		29
Other comprehensive income	30		25		61		49		31		26		92		75
Comprehensive income	$	58,481	$	35,387	$	91,611	$	60,466	$	81,572	$	67,807	$	173,183	$	128,273

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)


	Six Months Ended June 30						Nine Months Ended Sept. 30,
	2018			2017			2018			2017
Operating activities
Net income	$	91,550		$	60,417		$	173,091		$	128,198
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	98,128			97,126			150,403			144,664
Demand side management program amortization	837			837			1,255			1,255
Deferred income taxes	(2,306		)	48,099			14,395			101,388
Amortization of investment tax credits	(26		)	(66		)	(39		)	(99		)
Allowance for equity funds used during construction	(6,618		)	(4,004		)	(11,637		)	(6,457		)
Net derivative losses	31			31			47			47
Other, net	(5		)	10			(5		)	9
Changes in operating assets and liabilities:
Accounts receivable	(25,351		)	(12,210		)	(25,096		)	(25,134		)
Accrued unbilled revenues	2,329			(16,668		)	9,648			(13,682		)
Inventories	7,915			5,411			7,032			(2,845		)
Prepayments and other	671			7,028			641			19,361
Accounts payable	640			16,799			(935		)	7,817
Net regulatory assets and liabilities	46,163			(3,477		)	58,832			24,856
Other current liabilities	13,937			(2,896		)	12,972			19,748
Pension and other employee benefit obligations	(7,885		)	(21,946		)	(7,907		)	(21,638		)
Change in other noncurrent assets	4,397			(373		)	3,546			(1,697		)
Change in other noncurrent liabilities	(458		)	(2,351		)	(235		)	(18,690		)
Net cash provided by operating activities	223,949			171,767			386,008			357,101

Investing activities
Utility capital/construction expenditures	(478,352		)	(279,918		)	(621,641		)	(400,957		)
Allowance for equity funds used during construction	6,618			4,004			11,637			6,457
Investments in utility money pool arrangement	(46,000		)	—			(46,000		)	—
Repayments from utility money pool arrangement	111,000			—			111,000			—
Other, net	—			(493		)	—			(493		)
Net cash used in investing activities	(406,734		)	(276,407		)	(545,004		)	(394,993		)

Financing activities
Proceeds from short-term borrowings, net	132,000			56,000			35,000			(50,000		)
Proceeds from issuance of long-term debt, net							—			442,651
Borrowings under utility money pool arrangement	180,000			572,000			446,000			323,000
Repayments under utility money pool arrangement	(80,000		)	(511,000		)	(423,000		)	(323,000		)
Capital contributions from parent	360			45,000			181,484			45,000
Repayment of long-term debt	—			(18		)	—			(271,613		)
Dividends paid to parent	(60,008		)	(57,585		)	(90,705		)	(82,599		)
Other, net	(31		)	—			(31		)	—
Net cash provided by financing activities	172,321			104,397			148,748			83,439

Net change in cash and cash equivalents	(10,464		)	(243		)	(10,248		)	45,547
Cash and cash equivalents at beginning of period	10,871			844			10,871			844
Cash and cash equivalents at end of period	$	407		$	601		$	623		$	46,391

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(36,680	)	$	(40,450	)	$	(57,924	)	$	(58,581	)
Cash (paid) received for income taxes, net	(7,560		)	17,213			(15,251		)	37,899
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	43,286		$	34,529		$	54,601		$	40,861

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)


	June 30, 2018			Dec. 31, 2017			Sept. 30, 2018			Dec. 31, 2017
Assets
Current assets
Cash and cash equivalents	$	407		$	10,871		$	623		$	10,871
Accounts receivable, net	102,379			79,581			101,870			79,581
Accounts receivable from affiliates	4,764			1,297			4,085			1,297
Investments in utility money pool arrangement	—			65,000			—			65,000
Accrued unbilled revenues	127,475			129,804			120,156			129,804
Inventories	32,518			40,433			33,401			40,433
Regulatory assets	26,093			31,538			23,387			31,538
Derivative instruments	38,549			15,882			28,436			15,882
Prepaid taxes	15,710			15,025			15,821			15,025
Prepayments and other	10,219			10,341			10,137			10,341
Total current assets	358,114			399,772			337,916			399,772

Property, plant and equipment, net	5,434,187			5,095,609			5,539,200			5,095,609

Other assets
Regulatory assets	360,902			362,943			366,885			362,943
Derivative instruments	17,374			18,954			16,584			18,954
Other	3,710			11,266			4,602			11,266
Total other assets	381,986			393,163			388,071			393,163
Total assets	$	6,174,287		$	5,888,544		$	6,265,187		$	5,888,544

Liabilities and Equity
Current liabilities
Short-term debt	$	132,000		$	—		$	35,000		$	—
Borrowings under utility money pool arrangement	100,000			—			23,000			—
Accounts payable	184,825			211,756			191,874			211,756
Accounts payable to affiliates	15,036			22,577			17,308			22,577
Regulatory liabilities	123,303			68,835			112,585			68,835
Taxes accrued	51,965			35,243			53,453			35,243
Accrued interest	23,413			23,275			20,396			23,275
Dividends payable	30,697			26,753			40,071			26,753
Derivative instruments	3,565			3,565			3,565			3,565
Other	26,019			29,641			25,548			29,641
Total current liabilities	690,823			421,645			522,800			421,645

Deferred credits and other liabilities
Deferred income taxes	577,492			574,906			601,294			574,906
Regulatory liabilities	781,917			784,564			795,424			784,564
Asset retirement obligations	29,279			28,524			29,664			28,524
Derivative instruments	18,166			19,949			17,275			19,949
Pension and employee benefit obligations	82,326			90,266			82,369			90,266
Other	4,630			8,386			4,816			8,386
Total deferred credits and other liabilities	1,493,810			1,506,595			1,530,842			1,506,595

Commitments and contingencies
Capitalization
Long-term debt	1,830,508			1,829,941			1,830,796			1,829,941
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at June 30, 2018 and Dec. 31, 2017, respectively	—			—
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Sept. 30, 2018 and Dec. 31, 2017, respectively							—			—
Additional paid in capital	1,591,366			1,590,242			1,771,469			1,590,242
Retained earnings	569,186			541,588			610,655			541,588
Accumulated other comprehensive loss	(1,406		)	(1,467		)	(1,375		)	(1,467		)
Total common stockholder’s equity	2,159,146			2,130,363			2,380,749			2,130,363
Total liabilities and equity	$	6,174,287		$	5,888,544		$	6,265,187		$	5,888,544

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE COMPANY

Notes to Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of SPS as of ~~June~~Sept. 30, 2018 and Dec. 31, 2017; the results of its operations, including the components of net income and comprehensive income, for the three and ~~six~~nine months ended ~~June~~Sept. 30, 2018 and 2017; and its cash flows for the ~~six~~nine months ended ~~June~~Sept. 30, 2018 and 2017. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after ~~June~~Sept. 30, 2018 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2017 balance sheet information has been derived from the audited 2017 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2017. These notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the financial statements and notes thereto, included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2017, filed with the SEC on Feb. 23, 2018. Due to the seasonality of SPS’ electric sales, interim results are not necessarily an appropriate base from which to project annual results.


1.	Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the financial statements in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2017, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently Issued

Leases —In In February 2016, the Financial Accounting Standards Board (FASB) issued Leases, Topic 842 (Accounting Standards Update (ASU) No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. ~~SPS has not yet fully determined the impacts of implementation. However, adoption is expected to~~Adoption will occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and ~~proposed~~included in Targeted Improvements, Topic 842 ~~(Proposed~~ (ASU ~~2018-200)~~No. 2018-11). On Jan. 1, 2019, agreements ~~considered~~historically disclosed as operating leases for the use of ~~office space,~~real estate, equipment and ~~natural gas storage assets, as well as~~ certain fossil-fueled generating facilities operated under purchased power agreements (PPAs) ~~for fossil-fueled generating facilities~~ are expected to be recognized on the consolidated balance sheet. Other than first-time recognition of these types of operating leases on the balance sheet, the implementation is not expected to have a significant impact on SPS’ financial statements.

Recently Adopted

Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. SPS implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. Other than increased disclosures regarding revenues related to contracts with customers, the implementation did not have a ~~significant~~material impact on SPS’ financial statements. For related disclosures, see Note 12 to the financial statements.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are recognized in earnings. SPS implemented the guidance on Jan. 1, 2018 and the implementation did not have a material impact on its financial statements.

Presentation of Net Periodic Benefit Cost — In March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of the application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment, and the impacts of adoption will be limited to changes in classification of non-service costs in the statement of income. SPS implemented the new guidance on Jan. 1, 2018, and as a result, ~~$1.5~~$0.7 million and $2.2 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the income statement for the ~~six~~three and nine months ended ~~June~~Sept. 30, ~~2017.~~2017, respectively. Under a practical expedient permitted by the standard, SPS used benefit cost amounts disclosed for prior periods as the basis for retrospective application.


3.	Selected Balance Sheet Data


(Thousands of Dollars)	June 30, 2018			Dec. 31, 2017			Sept. 30, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	107,990		$	85,929		$	107,709		$	85,929
Less allowance for bad debts	(5,611		)	(6,348		)	(5,839		)	(6,348		)
	$	102,379		$	79,581		$	101,870		$	79,581


(Thousands of Dollars)	June 30, 2018		Dec. 31, 2017		Sept. 30, 2018		Dec. 31, 2017
Inventories
Materials and supplies	$	25,416	$	26,218	$	25,380	$	26,218
Fuel	7,102		14,215		8,021		14,215
	$	32,518	$	40,433	$	33,401	$	40,433


(Thousands of Dollars)	June 30, 2018			Dec. 31, 2017			Sept. 30, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	7,059,344		$	6,765,371		$	7,115,175		$	6,765,371
Construction work in progress	447,945			351,875			533,538			351,875
Total property, plant and equipment	7,507,289			7,117,246			7,648,713			7,117,246
Less accumulated depreciation	(2,073,102		)	(2,021,637		)	(2,109,513		)	(2,021,637		)
	$	5,434,187		$	5,095,609		$	5,539,200		$	5,095,609


4.	Income Taxes

Except to the extent noted below, Note 6 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2017 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:


	Six Months Ended June 30				Nine Months Ended Sept. 30,
	2018		2017		2018		2017
Federal statutory rate	21.0	%	35.0	%	21.0	%	35.0	%
State tax, net of federal tax effect	2.4		2.2
State tax (net of federal tax effect)					2.3		2.3
Increases (decreases) in tax from:
Regulatory differences - ARAM ^(a)	(4.2	)	—		(4.0	)	—
Regulatory differences - ARAM ^(b)	1.3		—
Regulatory differences - ARAM deferral ^(b)					1.7		—
Regulatory differences - reversal of prior quarters' ARAM deferral ^(b)					(0.2	)	—
Regulatory differences - other utility plant items	(1.4	)	(0.8	)	(1.3	)	(0.8	)
Tax credits, net of federal income tax expense	(0.7	)	(0.5	)
Other, net	0.1		0.4
Tax credits (net of federal income tax expense)					(0.7	)	(0.7	)
Other (net)					(1.8	)	0.1
Effective income tax rate	18.5	%	36.3	%	17.0	%	35.9	%


^(a)	The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.


^(b)	ARAM has been deferred when regulatory treatment has not been established. As ~~we receive~~SPS received direction from ~~our~~its regulatory commissions regarding the return of excess deferred taxes ~~(to our~~to customers, ~~resulting from~~ the ~~Tax Cuts and Jobs Act~~ARAM deferral was reversed. This resulted in a reduction to tax expense with a corresponding reduction to revenue.

~~(TCJA)), the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a corresponding reduction to revenue.~~

Federal Audits — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The ~~statutes~~statute of limitations applicable to Xcel Energy’s federal income tax returns expire as follows:



Tax Year(s)		Expiration
2009 ~~- 2011~~		~~December 2018~~
~~2012~~ - 2014		October 2019
2015		September 2019
2016		September 2020

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. ~~The IRS proposed an adjustment to the federal tax loss carryback claims~~In 2017 Xcel Energy and ~~in 2015 the IRS forwarded the issue to~~ the Office of Appeals (Appeals)~~. In 2017 Xcel Energy and Appeals~~ reached an agreement and the benefit related to the agreed upon portions was recognized. SPS did not accrue any income tax benefit related to this adjustment. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). ~~After evaluating the proposed adjustment~~ Xcel Energy filed a protest with the IRS. As of ~~June~~Sept. 30, 2018 the case has been forwarded to Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of ~~June~~Sept. 30, 2018, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:


(Millions of Dollars)	June 30, 2018		Dec. 31, 2017		Sept. 30, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	2.5	$	2.3	$	2.8	$	2.3
Unrecognized tax benefit — Temporary tax positions	1.6		2.0		1.6		2.0
Total unrecognized tax benefit	$	4.1	$	4.3	$	4.4	$	4.3

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:


(Millions of Dollars)	June 30, 2018			Dec. 31, 2017			Sept. 30, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(6.6	)	$	(5.9	)	$	(6.9	)	$	(5.9	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and audit resumes and state audits resume. As the IRS Appeals progresses and the IRS audit resumes, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $3 million.

~~The payable~~Payables for interest related to unrecognized tax benefits ~~is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2018 and Dec. 31, 2017~~ were not ~~material. No~~material and no amounts were accrued for penalties related to unrecognized tax benefits as of ~~June~~Sept. 30, 2018 or Dec. 31, 2017.


5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2017 and in Note 5 to the financial statements included in to SPS’ Quarterly ~~Report~~Reports on Form 10-Q for the quarterly ~~period~~periods ended March 31, 2018 and June 30, 2018, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Tax Reform — Regulatory Proceedings

The specific impacts of the TCJA on customer rates are subject to regulatory approval. ~~Each~~The following details the status of ~~the states~~regulatory decisions in each state where Xcel ~~Energy’s service areas, including~~Energy, which includes Texas and New Mexico, ~~have opened dockets to address the impacts of the TCJA.~~operates.

Texas — In June 2018, SPS, the Public Utility Commission of Texas (PUCT) Staff and various intervenors reached a settlement in the Texas electric rate case which included the impacts of the TCJA. The settlement reflects no change in customer rates or refunds and SPS’ actual capital structure, which SPS has informed the parties it intends to be up to a 57 percent equity ratio to offset the negative impacts on its credit metrics and potentially its credit ratings. A PUCT decision is expected in the fourth quarter of 2018.

New Mexico — In ~~February~~September 2018, ~~SPS indicated that~~ the ~~TCJA would reduce revenue requirements by approximately $11 million and recommended increasing~~New Mexico Public Regulation Commission (NMPRC) issued its ~~equity ratio to 58 percent to offset~~final order in SPS’ 2017 electric rate case, which included a refund of the ~~negative~~2018 impact of the ~~TCJA on its credit metrics and potentially its credit ratings. The impact of the TCJA is expected to be addressed as part of SPS’ pending New Mexico electric rate case.~~TCJA.

Pending Regulatory Proceedings — PUCT

Texas 2017 Electric Rate Case — In 2017, SPS filed a $54 million, or 5.8 percent, retail electric, non-fuel base rate increase case in Texas with each of its Texas municipalities and the PUCT. The request was based on a historic test year (HTY) ended June 30, 2017, a requested return on equity (ROE) of 10.25 percent, an electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent. ~~The request also reflects the acceleration of depreciation lives for the two generating units at the Tolk Generating Station from 2042 and 2045 to 2032.~~

In May 2018, SPS filed rebuttal testimony and revised its request to an overall increase in the annual base rate revenue of approximately $32 million, or 5.9 percent, net of the TCJA ~~(approximately $32 million after~~(after adjusting for a requested 58 percent equity ratio)

and other adjustments. This request would be equivalent to approximately $17 million after adjusting for the Transmission Cost Recovery Factor (TCRF) rider.

In June 2018, SPS, the PUCT Staff and various intervenors reached a settlement, which results in no overall change to SPS’ revenues after adjusting for the impact of the TCJA and the lower costs of long-term debt.

The following are key terms:

The ability to use an equity ratio that reflects SPS' actual capital structure, ~~which SPS has informed the parties it intends~~up to be 57 ~~percent to mitigate the impact of TCJA on credit metrics;~~percent;

A 9.5 percent ROE for the calculation of allowance for funds used during construction (AFUDC);

TCRF rider will remain in effect;

SPS will accelerate ~~depreciation rates for~~ the depreciable lives of Tolk ~~Generating Station~~ Units 1 and 2 ~~by 50 percent of the original request;~~from 2042 and 2045, respectively, to 2037; and

SPS agrees that it will file its next base rate case no later than Dec. 31, 2019.

A ~~reconciliation of~~PUCT decision on the settlement ~~is as follows:~~

(Millions of Dollars)
Original base rate request $ 69
Base rate revenue to be recovered through TCRF
(15 )
Net revenue request 54
Adjustment for TCJA and other items (37 )
Requested incremental revenue 17
Unspecified settlement adjustments (13 )
Accelerated depreciation (Tolk plant) (4 )
SPS' net revenue change $ —

Under the terms of the settlement, the final rates would not change from the current rates. However, SPS would be permitted to surcharge customers for unrecovered TCRF charges that were not billed during the period of Jan. 23, 2018 through June 10, 2018. A PUCT decision is expected in the ~~third~~fourth quarter of 2018.

~~Appeal of the Texas 2015 Electric Rate Case Decision~~ — In 2014, SPS had requested an overall retail electric revenue rate increase of $42 million. In 2015, the PUCT approved an overall rate decrease of approximately $4 million, net of rate case expenses. In April 2016, SPS filed an appeal with the Texas State District Court (District Court) challenging the PUCT’s order. In 2017, the District Court denied SPS’ appeal, and SPS appealed the District Court’s decision to the state Court of Appeals for the 7th Circuit. In 2018, the Court of Appeals upheld the District Court’s decision on the PUCT’s order, rejecting SPS’ appeal. As part of the settlement of the 2017 Texas rate case, SPS has agreed to end its appeal.

Pending Regulatory Proceeding — New Mexico Public Regulation Commission (NMPRC)

New Mexico 2017 Electric Rate Case — In October 2017, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $43 million. The request was based on a HTY ended June 30, 2017, a ROE of 10.25 percent, an equity ratio of 53.97 percent, a 35 percent federal income tax rate and a rate base of approximately $885 million, including rate base additions through Nov. 30, 2017.

In May 2018, SPS reduced its request to $27 million, net of the TCJA (approximately $11 ~~million)~~million, net of the requested higher equity ratio) and other

adjustments, based on a requested ROE of 10.25 percent and an equity ratio of 58.0 percent.

In June 2018, the New Mexico Hearing Examiner issued a recommended decision proposing an increase of $12 million based on a ROE of 9.4 percent and an equity ratio of 53.97 percent. She also denied SPS' requests to shorten depreciation lives related to Tolk Units 1 and 2 and Cunningham Unit 1. The Hearing Examiner rejected intervenor proposals to refund the impacts of the TCJA back to Jan. 1, 2018.

On Sept. 5, 2018, the NMPRC issued its final order resulting in a revenue increase of approximately $8 million, or 2.1 percent, effective Sept. 27, 2018, based on a ROE of 9.1 percent and a 51 percent equity ratio. The ~~following table summarizes certain parties’ proposed modifications to SPS’ request, SPS’ revised request, and~~NMPRC also ordered a refund of $10 million associated with the ~~Hearing Examiner’s recommendation:~~

(Millions of Dollars) NMPRC Staff Testimony NMAG Testimony SPS Rebuttal Testimony Hearing Examiner's Recommendation
SPS request $ 43
$ 43
$ 43
$ 43
Reduction to request for the impact of the TCJA (11 ) (11 ) (11 ) (11 )
SPS request, including the impact of the TCJA 32
32
32
32

ROE (4 ) (6 ) —
(5 )
Capital structure (7 ) (3 ) —
(3 )
Depreciation lives (Tolk and Cunningham plants) (3 ) (3 ) —
(3 )
Disallow rate case expenses (2 ) (3 ) (1 ) —
Regional transmission revenue and expense (adjustment for the impact of the TCJA):
Impact of the TCJA —
(3 ) —
(1 )
Aligning costs with transmission plant in rate base —
—
—
(1 )
Post test year plant (updated to actual) (1 ) (2 ) (3 ) —
Excess generation adjustment —
(1 ) —
(1 )
Other, net (4 ) (4 ) (1 ) (6 )
Recommended rate increase $ 11
$ 7
$ 27
$ 12

ROE 9.0 % 9.21 % 10.25 % 9.4 %
Equity ratio 52.0 % 53.97 % 58.0 % 53.97 %

TCJA impacts for the retroactive period of Jan. 1, 2018 through Sept. 27, 2018. SPS ~~anticipates~~recorded a ~~decision and implementation~~regulatory liability of ~~final rates~~$10 million for the customer refund in the third quarter of 2018.

On Sept. 7, 2018, SPS filed an appeal with the NMSC on the grounds that the NMPRC’s findings are contrary to the factual record and do not result in just and reasonable rates as required by law. In addition, SPS filed a motion for stay with the NMSC to delay the implementation of the retroactive TCJA refund until the NMSC issues its decision on SPS' appeal of the rate case order. SPS considers the refund illegal primarily because it violates the prohibition on retroactive ratemaking and results in rates that are not just and reasonable. On Sept. 26, 2018, the NMSC granted a temporary stay to delay the implementation of the retroactive refund until further order of the Court.

Appeal of the New Mexico 2016 Electric Rate Case Dismissal — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41 million, representing a total revenue increase of approximately 10.9 percent. The rate filing was based on a requested ROE of 10.1 percent, an equity ratio of 53.97 percent, an electric rate base of approximately $832 million and a future test year ~~ending~~ended June 30, 2018. In 2017, the NMPRC dismissed SPS’ rate case. SPS filed a notice of appeal in the ~~New Mexico Supreme Court.~~NMSC. A decision is not expected until the second half of 2019.

Pending Regulatory Proceeding — Federal Energy Regulatory Commission (FERC)

Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant funded, or “sponsored,” transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades. In 2016, the FERC granted SPP’s request to recover the charges not billed since 2008. SPP subsequently billed SPS approximately $13 million for these charges. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. In ~~November 2017, the FERC denied an SPS request for rehearing. In January~~July 2018, ~~SPS appealed the FERC request~~SPS’ appeal to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit)~~. SPS has filed~~ over the FERC rulings granting SPP the right to recover these charges was remanded to the ~~SPP~~FERC. As of September 2018, SPS’ recovery of these charges ~~as part~~(from 2008 through 2016) is being reviewed by the FERC, which is expected to rule in the first quarter of ~~the appeal. The appeal is currently pending.~~2019.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC denied SPS’ complaint. SPS sought rehearing in April 2018, and the FERC ~~approved the~~granted a rehearing ~~request~~ for purposes of further consideration in May 2018. The timing of FERC action on ~~May 7, 2018.~~the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.

SPP Filing to Assign GridLiance Facilities to SPS Rate Zone — In August 2018, SPP filed a request with the FERC to amend its OATT to include the costs of the GridLiance High Plains, LLC. facilities in the SPS rate zone. The FERC initially determined the facilities did not qualify as transmission facilities under the SPP OATT. SPP’s proposed tariff changes could result in an increase in the annual transmission revenue requirement (ATRR) of $9.5 million per year, with $6 million allocated to SPS’ retail customers. The remaining $3.5 million would be paid by other wholesale loads in the SPS rate zone. In September 2018, SPS protested the proposed SPP tariff charges, and asked the FERC to reject the SPP filing. The FERC is expected to take initial action in the fourth quarter of 2018.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 10, 11 and 1112 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2017 and in Notes 5 and 6 to the financial statements included in SPS’ Quarterly ~~Report~~Reports on Form 10-Q for the quarterly ~~period~~periods ended March 31, 2018 and June 30, 2018, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to SPS’ financial position.

PPAs

SPS purchases power from independent power producing entities that own natural gas fueled power plants for which SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.

SPS had approximately ~~897~~967 Megawatts (MW) of capacity under long-term PPAs as of ~~June~~Sept. 30, 2018 and 897 MW as of Dec. 31, 2017, with entities that have been determined to be variable interest entities. SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have various expiration dates through 2041.

Environmental Contingencies

Manufactured Gas Plant (MGP), Landfill or Disposal Sites — SPS is currently involved in investigating and/or remediating an MGP, landfill or other disposal site. SPS has identified one site where ~~contamination is present and where~~ investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities. SPS anticipates that the investigation or remediation activities will continue through at least ~~2018.~~2019. SPS accrued $0.1 million for the site as of ~~June~~Sept. 30, 2018 and Dec. 31, 2017, respectively. There may be insurance recovery and/or recovery from other ~~potentially~~ responsible parties that will offset any costs incurred. ~~SPS anticipates that any amounts spent will be fully recovered from customers.~~

Legal Contingencies

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

7. Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for SPS were as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2018			Year Ended Dec. 31, 2017			Three Months Ended Sept. 30, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	100		$	100		$	100		$	100
Amount outstanding at period end	100			—			23			—
Average amount outstanding	24			13			76			13
Maximum amount outstanding	100			100			100			100
Weighted average interest rate, computed on a daily basis	1.84		%	1.12		%	1.97		%	1.12		%
Weighted average interest rate at period end	1.85			N/A			1.99			N/A

Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool. Commercial paper outstanding for SPS was as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2018			Year Ended Dec. 31, 2017			Three Months Ended Sept. 30, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	400		$	400		$	400		$	400
Amount outstanding at period end	132			—			35			—
Average amount outstanding	32			69			63			69
Maximum amount outstanding	140			176			144			176
Weighted average interest rate, computed on a daily basis	2.25		%	1.13		%	2.25		%	1.13		%
Weighted average interest rate at period end	2.29			N/A			2.35			N/A

Letters of Credit — SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. As of ~~June~~Sept. 30, 2018 and Dec. 31, 2017, there were $2 million and $3 million, respectively, of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

As of ~~June~~Sept. 30, 2018, SPS had the following committed credit facility available (in millions of dollars):


Credit Facility ^(a)	Credit Facility ^(a)	Drawn ^(b)		Available		Credit Facility ^(a)	Drawn ^(b)		Available
$	400	$	134	$	266	400	$	37	$	363


^(a)	This credit facility expires in June 2021.


^(b)	Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding as of ~~June~~Sept. 30, 2018 and Dec. 31, 2017.


8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset value.

Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated and may result in Level 3 classification.

Electric commodity derivatives held by SPS include transmission congestion instruments, generally referred to as financial transmission rights (FTRs), purchased from SPP. FTRs purchased from a regional transmission organization (RTO) are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes the cleared prices for each FTR for the most recent auction.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited transparency in the auction process, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs, the limited transparency associated with the valuation of FTRs is insignificant to the financial statements of SPS.

Derivative Instruments Fair Value Measurements

SPS enters into derivative instruments, including forward contracts, for trading purposes and to manage risk in connection with changes in interest rates and electric utility commodity prices.

Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

As of ~~June~~Sept. 30, 2018, accumulated other comprehensive losses related to interest rate derivatives included immaterial net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations. This could include the purchase or sale of energy or energy-related products and FTRs.

The following table details the gross notional amounts of commodity FTRs as of ~~June~~Sept. 30, 2018 and Dec. 31, 2017:


(Amounts in Thousands) ^(a)	June 30, 2018	Dec. 31, 2017	Sept. 30, 2018	Dec. 31, 2017
Megawatt hours of electricity	12,941	4,251	8,594	4,251


^(a)	Amounts are not reflective of net positions in the underlying commodities.

Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were immaterial for each of the three and ~~six~~nine months ended ~~June~~Sept. 30, 2018 and 2017.

During the three and ~~six~~nine months ended ~~June~~Sept. 30, 2018, changes in the fair value of FTRs resulted in pre-tax net losses of $3.3 million and pre-tax net gains of ~~$13.0 million and $13.4~~$10.1 million, respectively, and were recognized as regulatory assets and liabilities. For the three and ~~six~~nine months ended ~~June~~Sept. 30, 2017, changes in the fair value of FTRs resulted in pre-tax net ~~gains~~losses of ~~$0.2~~$2.5 million and ~~$2.3~~$0.2 million, respectively, and were recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

There were immaterial FTR settlement ~~gains of $3.9 million~~losses and $3.4 million ~~were~~of FTR settlement gains recognized for the three and ~~six~~nine months ended ~~June~~Sept. 30, 2018, respectively, and were recorded to electric fuel and purchased power. For the three and ~~six~~nine months ended ~~June~~Sept. 30, 2017, FTR settlement losses of $2.2 million and gains of ~~$1.2 million and $2.4~~$0.1 million, respectively, were recognized and recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

SPS had no derivative instruments designated as fair value hedges during the three and ~~six~~nine months ended ~~June~~Sept. 30, 2018 and 2017. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations — SPS continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of SPS’ own credit risk when determining the fair value of derivative liabilities, the impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.

SPS employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. As of ~~June~~Sept. 30, 2018, ~~six~~two of SPS’ most significant counterparties, comprising ~~$25.7~~$16.9 million or 5034 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the most significant counterparties, comprising $10.7 million or 22 percent of this credit exposure, were not rated by ~~Standard & Poor’s, Moody’s or Fitch Ratings,~~these external agencies, but based on ~~SPS’~~SPS’s internal analysis, had credit quality consistent with investment grade. The one remaining significant counterparty, comprising $0.2 million or less than 1 percent of this credit exposure, had credit quality less than investment grade, based on ratings from internal analysis. All seven of these significant counterparties are municipal or cooperative electric entities or other utilities.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis as of ~~June~~Sept. 30, 2018:


	June 30, 2018														Sept. 30, 2018
	Fair Value						Fair Value Total			Counterparty Netting ^(b)					Fair Value							Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3				Total				Level 1		Level 2		Level 3				Total			Counterparty Netting ^(b)
Current derivative assets							Fair Value Total
Other derivative instruments:										Counterparty Netting ^(b)												Fair Value Total
Electric commodity	$	—	$	—	$	35,897	$	35,897		$	(508	)	$	35,389	$	—	$	—	$	25,666		$	25,666	$	(389	)	$	25,277
Total current derivative assets	$	—	$	—	$	35,897	$	35,897		$	(508	)	35,389		$	—	$	—	$	25,666		$	25,666	$	(389	)	25,277
PPAs ^(a)													3,160														3,159
Current derivative instruments													$	38,549													$	28,436
Noncurrent derivative assets
PPAs ^(a)													$	17,374													$	16,584
Noncurrent derivative instruments													$	17,374													$	16,584
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	508	$	508		$	(508	)	$	—	$	—	$	—	$	389		$	389	$	(389	)	$	—
Total current derivative liabilities	$	—	$	—	$	508	$	508		$	(508	)	—		$	—	$	—	$	389		$	389	$	(389	)	—
PPAs ^(a)													3,565														3,565
Current derivative instruments													$	3,565													$	3,565
Noncurrent derivative liabilities
PPAs ^(a)													$	18,166													$	17,275
Noncurrent derivative instruments													$	18,166													$	17,275


^(a)	During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at ~~June~~Sept. 30, 2018. At ~~June~~Sept. 30, 2018, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis as of Dec. 31, 2017:



	Dec. 31, 2017
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	14,717	$	14,717	$	(1,994	)	$	12,723
Total current derivative assets	$	—	$	—	$	14,717	$	14,717	$	(1,994	)	12,723
PPAs ^(a)												3,159
Current derivative instruments												$	15,882
Noncurrent derivative assets
PPAs ^(a)												$	18,954
Noncurrent derivative instruments												$	18,954
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,994	$	1,994	$	(1,994	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,994	$	1,994	$	(1,994	)	—
PPAs ^(a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs ^(a)												$	19,949
Noncurrent derivative instruments												$	19,949


^(a)	During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three and ~~six~~nine months ended ~~June~~Sept. 30, 2018 and 2017:



	Three Months Ended June 30,						Three Months Ended Sept. 30,
(Thousands of Dollars)	2018			2017			2018			2017
Balance at April 1	$	5,343		$	1,192
Balance at July 1							$	35,389		$	28,665
Purchases	18,668			35,822			3,169			43
Settlements	(14,798		)	(14,098		)	(10,068		)	(9,939		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	26,176			5,749
Balance at June 30	$	35,389		$	28,665
Net (losses) gains recognized as regulatory assets and liabilities							(3,213		)	1,669
Balance at Sept. 30							$	25,277		$	20,438



	Six Months Ended June 30						Nine Months Ended Sept. 30,
(Thousands of Dollars)	2018			2017			2018			2017
Balance at Jan. 1	$	12,723		$	1,955		$	12,723		$	1,955
Purchases	19,348			39,333			22,517			39,376
Settlements	(25,237		)	(30,498		)	(35,305		)	(40,437		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	28,555			17,875			25,342			19,544
Balance at June 30	$	35,389		$	28,665
Balance at Sept. 30							$	25,277		$	20,438

SPS recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and ~~six~~nine months ended ~~June~~Sept. 30, 2018 and 2017.

Fair Value of Long-Term Debt

As of ~~June~~Sept. 30, 2018 and Dec. 31, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:


	June 30, 2018				Dec. 31, 2017				Sept. 30, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,830,508	$	1,858,497	$	1,829,941	$	2,001,992	$	1,830,796	$	1,832,158	$	1,829,941	$	2,001,992

The fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of ~~June~~Sept. 30, 2018 and Dec. 31, 2017, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.


9.	Other Expense, Net

Other expense, net consisted of the following:


	Three Months Ended June 30						Six Months Ended June 30						Three Months Ended Sept. 30						Nine Months Ended Sept. 30,
(Thousands of Dollars)	2018			2017			2018			2017			2018			2017			2018			2017
Interest income	$	356		$	147		$	298		$	192		$	473		$	296		$	771		$	488
Other nonoperating income	1			1			3			—			—			1			2			—
Other nonoperating expense	—			—			—			(1		)	(1		)	—			—			—
Insurance policy expense	(12		)	(12		)	(24		)	(24		)	(11		)	(12		)	(35		)	(36		)
Benefits non-service cost	(1,127		)	(749		)	(1,763		)	(1,498		)	(1,487		)	(749		)	(3,250		)	(2,247		)
Other expense, net	$	(782	)	$	(613	)	$	(1,486	)	$	(1,331	)	$	(1,026	)	$	(464	)	$	(2,512	)	$	(1,795	)


10.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)


	Three Months Ended June 30												Three Months Ended Sept. 30
	2018			2017			2018			2017			2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,430		$	2,440		$	280		$	219		$	2,429		$	2,439		$	280		$	219
Interest cost ^(a)	4,602			4,927			411			415			4,603			4,928			410			415
Expected return on plan assets ^(a)	(7,082		)	(6,971		)	(616		)	(589		)	(7,082		)	(6,971		)	(615		)	(589		)
Amortization of prior service credit ^(a)	(34		)	—			(100		)	(100		)	(34		)	—			(101		)	(100		)
Amortization of net loss (gain) ^(a)	3,517			3,245			(113		)	(155		)	3,517			3,245			(114		)	(155		)
Net periodic benefit cost (credit)	3,433			3,641			(138		)	(210		)	3,433			3,641			(140		)	(210		)
Credits not recognized due to the effects of regulation	761			574			—			—
(Costs) credits not recognized due to the effects of regulation													(468		)	553			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,194		$	4,215		$	(138	)	$	(210	)	$	2,965		$	4,194		$	(140	)	$	(210	)


	Six Months Ended June 30												Nine Months Ended Sept. 30
	2018			2017			2018			2017			2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	4,860		$	4,880		$	559		$	438		$	7,289		$	7,319		$	839		$	657
Interest cost ^(a)	9,205			9,855			821			830			13,808			14,783			1,231			1,245
Expected return on plan assets ^(a)	(14,164		)	(13,942		)	(1,231		)	(1,178		)	(21,246		)	(20,913		)	(1,846		)	(1,767		)
Amortization of prior service credit ^(a)	(69		)	—			(201		)	(200		)	(103		)	—			(302		)	(300		)
Amortization of net loss (gain) ^(a)	7,034			6,490			(226		)	(310		)	10,551			9,735			(340		)	(465		)
Net periodic benefit cost (credit)	6,866			7,283			(278		)	(420		)	10,299			10,924			(418		)	(630		)
Credits not recognized due to the effects of regulation	1,735			722			—			—			1,267			1,275			—			—
Net benefit cost (credit) recognized for financial reporting	$	8,601		$	8,005		$	(278	)	$	(420	)	$	11,566		$	12,199		$	(418	)	$	(630	)

^(a)The components of net periodic cost other than the service cost component are included in the line item “other expense, net” in the income statement or capitalized on the balance sheet as a regulatory asset.

In January 2018, contributions of $150 million were made across four of Xcel Energy’s pension plans, of which $8.0 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2018.


11.	Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three and ~~six~~nine months ended ~~June~~Sept. 30, 2018 and 2017 were as follows:


	Three Months Ended June 30, 2018									Three Months Ended Sept. 30, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at April 1	$	(764	)	$	(672	)	$	(1,436	)
Accumulated other comprehensive loss at July 1										$	(752	)	$	(654	)	$	(1,406	)
Losses reclassified from net accumulated other comprehensive loss	12			18			30			13			18			31
Net current period other comprehensive income	12			18			30			13			18			31
Accumulated other comprehensive loss at June 30	$	(752	)	$	(654	)	$	(1,406	)
Accumulated other comprehensive loss at Sept. 30										$	(739	)	$	(636	)	$	(1,375	)


	Three Months Ended June 30, 2017									Three Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at April 1	$	(669	)	$	(597	)	$	(1,266	)
Accumulated other comprehensive loss at July 1										$	(659	)	$	(582	)	$	(1,241	)
Losses reclassified from net accumulated other comprehensive loss	10			15			25			10			16			26
Net current period other comprehensive income	10			15			25			10			16			26
Accumulated other comprehensive loss at June 30	$	(659	)	$	(582	)	$	(1,241	)
Accumulated other comprehensive loss at Sept. 30										$	(649	)	$	(566	)	$	(1,215	)


	Six Months Ended June 30, 2018									Nine Months Ended Sept. 30, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(776	)	$	(691	)	$	(1,467	)	$	(776	)	$	(691	)	$	(1,467	)
Losses reclassified from net accumulated other comprehensive loss	24			37			61			37			55			92
Net current period other comprehensive income	24			37			61			37			55			92
Accumulated other comprehensive loss at June 30	$	(752	)	$	(654	)	$	(1,406	)
Accumulated other comprehensive loss at Sept. 30										$	(739	)	$	(636	)	$	(1,375	)


	Six Months Ended June 30, 2017									Nine Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(678	)	$	(612	)	$	(1,290	)	$	(678	)	$	(612	)	$	(1,290	)
Losses reclassified from net accumulated other comprehensive loss	19			30			49			29			46			75
Net current period other comprehensive income	19			30			49			29			46			75
Accumulated other comprehensive loss at June 30	$	(659	)	$	(582	)	$	(1,241	)
Accumulated other comprehensive loss at Sept. 30										$	(649	)	$	(566	)	$	(1,215	)

Reclassifications from accumulated other comprehensive loss for the three and ~~six~~nine months ended ~~June~~Sept. 30, 2018 and 2017 were as follows:


	Amounts Reclassified from Accumulated Other Comprehensive Loss								Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2018				Three Months Ended June 30, 2017				Three Months Ended Sept. 30, 2018				Three Months Ended Sept. 30, 2017
Losses on cash flow hedges:
Interest rate derivatives	$	16		^(a)	$	16		^(a)	$	16		^(a)	$	16		^(a)
Total, pre-tax	16				16				16				16
Tax benefit	(4		)		(6		)		(3		)		(6		)
Total, net of tax	12				10				13				10
Defined benefit pension and postretirement losses:
Amortization of net loss	23			^(b)	24			^(b)	23			^(b)	24			^(b)
Total, pre-tax	23				24				23				24
Tax benefit	(5		)		(9		)		(5		)		(8		)
Total, net of tax	18				15				18				16
Total amounts reclassified, net of tax	$	30			$	25			$	31			$	26


	Amounts Reclassified from Accumulated Other Comprehensive Loss								Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017				Nine Months Ended Sept. 30, 2018				Nine Months Ended Sept. 30, 2017
Losses on cash flow hedges:
Interest rate derivatives	$	31		^(a)	$	31		^(a)	$	47		^(a)	$	47		^(a)
Total, pre-tax	31				31				47				47
Tax benefit	(7		)		(12		)		(10		)		(18		)
Total, net of tax	24				19				37				29
Defined benefit pension and postretirement losses:
Amortization of net loss	47			^(b)	48			^(b)	70			^(b)	72			^(b)
Total, pre-tax	47				48				70				72
Tax benefit	(10		)		(18		)		(15		)		(26		)
Total, net of tax	37				30				55				46
Total amounts reclassified, net of tax	$	61			$	49			$	92			$	75

^(a)Included in interest charges.


^(b)	Included in the computation of net periodic pension and postretirement benefit costs. See Note 10 to the financial statements for details regarding these benefit plans.

12. Revenues

SPS principally generates revenue from the generation, transmission, distribution and sale of electricity to wholesale and retail customers. Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. SPS recognizes revenue in an amount that corresponds directly to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Contract terms are generally short-term in nature, and as such SPS does not recognize a separate financing component of its collections from customers. SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.

SPS participates in SPP. SPS recognizes sales to both native load and other end use customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are recorded on a gross basis. Other revenues and charges related to participating and transacting in RTOs are also recorded on a net basis in cost of sales. SPS has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.

When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met (including collection within 24 months), revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenue is recorded on a gross basis and is disclosed separate from revenue from contracts with customers in the period earned.

In the following tables, regulated electric revenue is classified by the type of goods/services rendered and market/customer type.


	Three Months Ended				Three Months Ended
(Thousands of Dollars)	June 30, 2018		June 30, 2017		Sept. 30, 2018		Sept. 30, 2017
Major product lines
Revenue from contracts with customers:
Residential	$	85,107	$	84,188	$	114,387	$	113,380
Commercial and industrial (C&I)	200,760		215,805		229,457		241,295
Other	11,363		12,242		12,983		13,399
Total retail	297,230		312,235		356,827		368,074
Wholesale	115,629		101,893		117,949		116,635
Transmission	58,970		56,394		60,726		56,143
Other	2,858		2,065		1,792		3,862
Total revenue from contracts with customers	474,687		472,587		537,294		544,714
Alternative revenue and other	6,651		7,209		2,769		6,909
Total revenues	$	481,338	$	479,796	$	540,063	$	551,623


	Six Months Ended				Nine Months Ended
(Thousands of Dollars)	June 30, 2018		June 30, 2017		Sept. 30, 2018		Sept. 30, 2017
Major product lines
Revenue from contracts with customers:
Residential	$	165,156	$	163,789	$	279,543	$	277,169
C&I	396,531		416,762		625,988		658,057
Other	21,027		21,854		34,010		35,253
Total retail	582,714		602,405		939,541		970,479
Wholesale	208,861		193,034		326,810		309,669
Transmission	114,616		110,572		175,342		166,715
Other	10,389		4,010		12,181		7,872
Total revenue from contracts with customers	916,580		910,021		1,453,874		1,454,735
Alternative revenue and other	11,990		29,847		14,759		36,756
Total revenues	$	928,570	$	939,868	$	1,468,633	$	1,491,491

Item 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for SPS is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on SPS’ financial condition, results of operations, and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited financial statements and the related notes to the financial statements. Due to the seasonality of SPS’ electric sales, such interim results are not necessarily an appropriate base from which to project annual results.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including our 2018 earnings per share

guidance, the TCJA’s impact to SPS and its customers, long-term earnings per share and dividend growth rate, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including SPS’ Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2017, and subsequent securities ~~filings,~~filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: changes in environmental laws and regulations; unusual weather and climate change, including compliance with any accompanying legislative and regulatory changes; ability to recover costs from customers; actions of credit rating agencies; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; ~~business conditions in the~~availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; operational safety; successful long-term operational planning; commodity risks associated with energy ~~industry; including the risk~~markets and production; costs of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather;potential regulatory penalties; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital;fuel costs; and employee work force factors.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin. Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from the most directly comparable measure calculated and presented in accordance with GAAP. SPS’ management uses non-GAAP measures internally for financial planning and analysis, for reporting of results to the Board of Directors, and when communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our operating performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric Margins

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various recovery mechanisms, and as a result, changes in these expenses are offset in operating revenues. Management believes electric margin provides the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses.

These margins can be reconciled to operating income, a GAAP measure, by including operating and maintenance (O&M) expenses, demand side management (DSM) expenses, depreciation and amortization, and taxes (other than income taxes).

Results of Operations

SPS’ net income was approximately ~~$92~~$173 million for 2018 year-to-date, compared with approximately ~~$60~~$128 million for the same period in 2017. The year-to-date increase was ~~largely~~primarily due to higher AFUDC related to the Hale County wind project, timing of O&M expenses, the favorable impact of weather, sales growth, and lower interest expense, partially offset by higher depreciation expense.

Electric Revenues and Margin

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Changes in fuel or purchased power costs can impact earnings as the fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses. The following tables detail the electric revenues and margin:


	Six Months Ended June 30						Nine Months Ended Sept. 30
(Millions of Dollars)	2018			2017			2018			2017
Electric revenues before impact of the TCJA	$	950		$	940		$	1,513		$	1,491
Electric fuel and purchased power	(516		)	(522		)	(802		)	(816		)
Electric margin before impact of the TCJA	$	434		$	418		$	711		$	675
Impact of the TCJA (offset as a reduction in income tax expense)	(17		)	—			(38		)	—
Electric margin	$	417		$	418		$	673		$	675

The following tables summarize the components of the changes in electric revenues and electric margin for the ~~six~~nine months ended ~~June~~Sept. 30, 2018:

Electric ~~Revenues~~

Revenue


(Millions of Dollars)	2018 vs 2017			2018 vs 2017
Fuel and purchased power cost recovery	$	(53	)	$	(72	)
Firm wholesale	(12		)	(12		)
Trading	36			42
Wholesale transmission revenue	17			25
Estimated impact of weather	11			18
Sales Growth				5
Demand revenue				5
Other, net	11			11
Total increase in electric revenues before impact of the TCJA	$	10		$	22
Impact of TCJA (offset as a reduction in income tax expense)	(21		)	(44		)
Total decrease in electric revenues	$	(11	)	$	(22	)

Electric Margin


(Millions of Dollars)	2018 vs 2017			2018 vs 2017
Firm wholesale	$	(12	)	$	(12	)
Estimated impact of weather	11			18
Wholesale transmission revenue, net of costs	7			12
Sales growth				5
Demand revenue				5
Other, net	10			8
Total increase in electric margin before impact of the TCJA	$	16		$	36
Impact of TCJA (offset as a reduction in income tax expense)	(17		)	(38		)
Total decrease in electric margin	$	(1	)	$	(2	)

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses decreased ~~$13~~$7 million, or ~~9.2~~3.5 percent, for 2018 year-to-date. The decrease primarily relates to timing of O&M ~~expenses, including~~expenses.

Depreciation and Amortization — Depreciation and amortization increased $5 million, or 3.7 percent for 2018 year-to-date. The increase primarily relates to an increase in capital investments and planned ~~maintenance and overhauls at various generation facilities.~~system investments.

Income Taxes — Income tax expense decreased ~~$14~~$36 million for the first ~~six~~nine months of 2018 compared with the same period in 2017. The decrease was primarily driven by a lower federal tax rate due to the TCJA and an increase in plant-related regulatory differences related to ARAM (net of deferrals). The ETR was ~~18.5~~17.0 percent for the first ~~six~~nine months of 2018, compared with ~~36.3~~35.9 percent for the same period in 2017. The lower ETR in 2018 is primarily due to the items referenced above. See Note 4 to the financial statements.

AFUDC, Equity and Debt — AFUDC increased $3 million for the third quarter of 2018 and increased $7 million year-to-date. The increase was primarily due to the Hale wind project and other capital investments.

Interest Charges — Interest charges decreased ~~$1 million, or 6.0 percent for the second quarter of 2018, and decreased~~ $4 million, or ~~8.7~~6.6 percent, year-to-date. The decrease was related to refinancing at lower interest rates, partially offset by higher debt levels to fund capital investments.

Public Utility Regulation

Except to the extent noted below and in Note 5 in the notes to the financial statements, the circumstances set forth in Public Utility Regulation included in Item 1 of SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2017 and in Public Utility Regulation included in Item 2 of SPS’ Quarterly ~~Report~~Reports on Form 10-Q for the quarterly ~~period~~periods ended March 31, 2018 and June 30, 2018, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

Texas State Right of First Refusal (ROFR) Request for Declaratory Order — In February 2017, SPS and SPP filed a joint petition with the PUCT for a declaratory order regarding SPS’ ROFR. SPS contended that Texas law grants an incumbent electric utility, operating in areas outside of Electric Reliability Council of Texas, the ROFR to construct new transmission facilities located in the utility’s service area. SPP stated that Texas law does not provide a clear statement regarding the ROFR for incumbent utilities and therefore SPP was abiding by the portion of its OATT, which requires competitive solicitation to construct and operate new transmission facilities within areas of Texas’ SPP footprint.

In October 2017, the PUCT issued an order finding that SPS does not possess an exclusive right to construct and operate transmission facilities within its service area. In January 2018, SPS and two other parties filed appeals of the PUCT’s order in the Texas State District Court. ~~The appeals have been consolidated and~~In September 2018, the ~~case is being briefed.~~

~~TUCO Substation~~District Court affirmed the PUCT’s ROFR order. SPS plans to ~~Yoakum County Substation to Hobbs Plant Substation 345 KV Transmission Line~~ — SPS has received certificates of convenience and necessity for the three segments of the TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 KV transmission line, which are expected to be in servicefile an appeal in the ~~second~~fourth quarter of 2020. This 345 KV transmission line is part of a larger project which includes an additional 345 KV transmission line from the Hobbs Plant Substation to the China Draw Substation, which was placed in service in May 2018. ~~The estimated total investment for these transmission lines is approximately $402 million.~~

~~Wind Proposals~~ — In 2017, SPS filed proposals with the NMPRC and the PUCT to build, own and operate 1,000 MW of new wind generation through two wind farms (the Hale wind project in Texas and the Sagamore wind project in New Mexico) for a cost of approximately $1.6 billion. In addition, the proposal includes a purchased power agreement for 230 MW of wind. SPS’ wind proposal was approved by both the NMPRC and the PUCT during 2018.

Summary of Recent Federal Regulatory Developments

FERC

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2017 and Quarterly ~~Report~~Reports on Form 10-Q for the quarterly ~~period~~periods ended March 31, 2018 and June 30, 2018. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

Xcel Energy, which includes SPS, attempts to mitigate the risk of regulatory penalties through formal training on

prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of ~~June~~Sept. 30, 2018, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No changes in SPS’ internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, SPS’ internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

Additional Information

See Note 6 to the financial statements for further discussion of legal claims and environmental proceedings. See Part I Item 2 and Note 5 to the financial statements for a discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

SPS’ risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2017, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 6 — EXHIBITS



*	Indicates incorporation by reference



3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3.01 to Form 10-Q for the quarter ended Sept. 30, 2017 (file no. 001-03789)).
3.02*	By-Laws of SPS as Amended and Restated on Sept. 26, 2013 (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03789)).
~~10.01~~*	Seventh Amendment dated May 7, 2018 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.01 to Form 10-Q of Xcel Energy for the quarter ended June 30, 2018 (file no. 001-03034)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from SPS’ Quarterly Report on Form 10-Q for the quarter ended ~~June~~Sept. 30, 2018 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Statements of Income, (ii) the Statements of Comprehensive Income (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) Notes to Financial Statements, and (vi) document and entity information.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		Southwestern Public Service Company

~~July 27,~~Oct. 26, 2018	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

2827



(Millions of Dollars)
Original base rate request	$	69
Base rate revenue to be recovered through TCRF	(15		)
Net revenue request	54
Adjustment for TCJA and other items	(37		)
Requested incremental revenue	17
Unspecified settlement adjustments	(13		)
Accelerated depreciation (Tolk plant)	(4		)
SPS' net revenue change	$	—



(Millions of Dollars)	NMPRC Staff Testimony			NMAG Testimony			SPS Rebuttal Testimony			Hearing Examiner's Recommendation
SPS request	$	43		$	43		$	43		$	43
Reduction to request for the impact of the TCJA	(11		)	(11		)	(11		)	(11		)
SPS request, including the impact of the TCJA	32			32			32			32

ROE	(4		)	(6		)	—			(5		)
Capital structure	(7		)	(3		)	—			(3		)
Depreciation lives (Tolk and Cunningham plants)	(3		)	(3		)	—			(3		)
Disallow rate case expenses	(2		)	(3		)	(1		)	—
Regional transmission revenue and expense (adjustment for the impact of the TCJA):
Impact of the TCJA	—			(3		)	—			(1		)
Aligning costs with transmission plant in rate base	—			—			—			(1		)
Post test year plant (updated to actual)	(1		)	(2		)	(3		)	—
Excess generation adjustment	—			(1		)	—			(1		)
Other, net	(4		)	(4		)	(1		)	(6		)
Recommended rate increase	$	11		$	7		$	27		$	12

ROE	9.0		%	9.21		%	10.25		%	9.4		%
Equity ratio	52.0		%	53.97		%	58.0		%	53.97		%